Petroleum source rocks
Petroleum source rocks must contain sufficient quantities of sedimentary organic matter with a requisite ratio of hydrogen to carbon. In thermally immature rocks, sedimentary organic matter is dominated by kerogen (organic matter insoluble in common organic solvents) with small amounts of bitumen. Bitumen is organic matter soluble in organic solvents, and the term is used here in a restricted sense for oil generated in petroleum source rocks before it is expelled.
Living organisms and their metabolic processes form sedimentary organic matter. Durand (1980) recognized that organic matter decomposes in the water column and in sediments, reducing the quantity and quality (hydrogen-richness) of the organic matter preserved in rocks. Organisms attack sedimentary organic matter for its carbon and hydrogen and metabolically convert some of it to simple molecules (e.g., CO2, H2O, CH4, NH3, N2, and H2S). Abiological oxidation also forms CO2 and H2O. These compounds are nonhydrocarbons (except for methane, CH4) and often escape early in the depositional and burial process. Therefore, the organic residue preserved in rocks and available for thermal conversio to fossil fuels represents only a small proportion of the original biological input. An even lower percentage of this buried fraction is converted to petroleum (oil and gas), expelled, migrated, concentrated, and trapped in reservoirs.
Petroleum source rocks are evaluated by their carbon richness as total organic carbon (TOC) in weight percent (wt. %). They are also evaluated by their hydrogen richness, or quality, as atomic H/C or, using Rock-Eval pyrolysis, as hydrogen index (HI), which is the ratio of pyrolyzable hydrocarbon mass to rock mass. Thermally immature hydrogen-rich organic matter (H/C > 1 or HI > 300) has oil-generative potential, whereas lower hydrogen content usually denotes gas-generative potential.
Heat transforms thermally immature sedimentary organic matter to oil and gas. This thermal maturation process is a function of time and temperature. The time-temperature factor may be insufficient to convert even the most oil-prone organic matter to petroleum (thermal immaturity), or it may generate petroleum (thermal maturity) or generate, expel, and overheat the residual organic matter, leaving only charred carbon (thermal postmaturity) in the source rock. Heating is related to burial depth, crustal tectonics, and proximity to igneous bodies.
Lopatin (1971) first described maturation modeling by calculating time-temperature indices for coals, basing his calculations on conversion kinetics of vitrinite, a gas-generative organic rock constituent (maceral). Waples (1980) brought the Lopatin method to English-reading geologists not fluent in Russian and applied "vitrinite kinetics" to petroleum generation. Subsequently, Waples (1985) provided adjustments that accommodate some of the variations in oil-prone organic matter not considered in Lopatin's coal studies. Ungerer and Pelet (1987) (see also Tissot et al., 1987) revolutionized the technique by introducing kinetics based on pyrolytically determined activation energies for oil-generative organic matter assemblages. An activation energy is the amount of energy required for a chemical reaction to proceed. In sedimentary organic matter conversion to petroleum, many reactions take place. However, because of chemical complications inherent when many different reactions occur simultaneously and sequentially, as in sedimentary organic matter conversion to petroleum, the use of experimentally derived pyrolysis activation energies is a practical way to calculate realistic conversion rates. Burnham et al. (1988) have further developed the method.
At any designated location such as a well site, the Lopatin method enhanced by the input of pyrolysis activation energies requires (1) burial history for strata including source rock candidates, (2) measured or estimated geothermal gradient(s), (3) sediment compaction, and (4) thermal conductivities for the lithostratigraphic units. The simulated maturation process integrates temperatures through time for stratigraphic units of interest.
Thermal maturation indicators (Heroux et al., 1979) for calibrating simulation models include vitrinite reflectance (R0), thermal alteration index (TAI) from palynomorphs, clay crystallinity, and hydrocarbon molecular ratios. Other methods for calibration include the conodont alteration index (CAI) (Epstein et al., 1977; Rejebian et al., 1987), Rock-Eval Tmax (Tissot and Welte, 1984; Peters, 1986), the porphyrin maturity parameter (Sundararaman et al., 1988), and biomarker ratios (Mackenzie, 1984). Each technique has limits in sample requirements, thermal resolution, and the thermal range in which it can be applied with accuracy. Sensitivity studies demonstrate that reconstruction of the local paleoheat flow (geothermal gradients) through the geological time of i terest is often the source of the greatest discrepancies between calculated maturities and thermal maturation indicators. Oils frequently carry gas chromatographic (GC) signatures useful for correlation to source rock extracts (thermal or solvent). These signatures are detectable with capillary column GC or may require the higher resolution available with mass spectrometry (GCMS). Reservoir oils and extracted bitumens contain source rock information. This "molecular stratigraphy" can reveal depositional features of petroleum source rocks, such as marine or lacustrine, clay rich or clay poor, redox potential of waters, and in some cases, the age of the source rock (using age-diagnostic biomarkers).
The petroleum yield of source rocks is related to the richness and quality of its incorporated sedimentary organic matter. Several methods have been proposed for determining potential volumetric yields and percentage of conversion of source rocks (e.g., Tissot et al., 1980; Tissot and Welte, 1984; Peters, 1986; Cooles et al., 1986; Tissot et al., 1987; Baskin, 1990).
Bitumen generated in source rocks saturates the source rock porosity. In source rocks with sufficient quantities of generated bitumen, the primarily physical process of expulsion may follow depending upon (1) the porosity, strength, and composition (e.g., clay, carbonate, or evaporite) of the source rock and its adjoining strata; (2) the concentration and distribution of kerogen (e.g., layered or disseminated); (3) whether the bitumen or mineral matrix is load bearing; (4) the properties of generated products (e.g., gas pressure and viscosity); and (5) the heating rate.
Recently, an evaluation of depositional controls, distribution, and effectiveness of the world's source rocks has been provided by Ulmishek and Klemme (1990). New schemes are emerging for evaluating petroleum generative potential in basins (Tissot et al., 1980; Demaison and Huizinga, in press).